1. Field of the Invention
This invention relates generally to the separation of gases, and more particularly, to an improved method and system for the purification of a sour gas stream by the bulk removal of CO.sub.2 and H.sub.2 S in a manner which substantially lowers costs. The invention also provides a method for prevention of sulphur deposition in piping and equipment commonly found in lean gas streams with high H.sub.2 S and CO.sub.2 concentrations.
2. Description of Related Art
Methods for bulk removal of H.sub.2 S and CO.sub.2 (acid gas) from a sour gas stream are well known, and include solvent-based Sour Gas Treating Units (SGTU), Ryan-Holmes, Rectisol, and other processes. The SGTU uses either an amine or physical solvent for removing the acid gas from the gas stream. The Ryan-Holmes process recirculates a lean oil additive to alter the solubility of the components in the system to prevent CO.sub.2 freezing problems in the fractionation column while removing H.sub.2 S and CO.sub.2. The Rectisol process uses a refrigerated methanol system for removal of acid gas by physical absorption. See, for example, Holmes, A. S.; et al., "Process Improves Acid Gas Separation"; Hydrocarbon Processing, p. 131, May 1982; and "Advantages of Rectisol-Wash Process in Selective H.sub.2 S Removal from Gas Mixtures", Line-Reports in Science and Technology, 18, 1973.
In 1962, Shell started up the Waterton Gas Plant near Pincher Creek, which had a "Low Temperature Flash" system. It liquified H.sub.2 S at low temperatures, then flashed the H.sub.2 S off at a lower pressure. This was effective while the H.sub.2 S concentration was high in the inlet gas stream.
Examples of such known methods and systems for the bulk removal of H.sub.2 S and CO.sub.2 from a sour gas are disclosed in U.S. Pat. Nos., such as 3,417,572 to Pryor, which discloses the separation of H.sub.2 S from CO.sub.2 by distillation; 4,097,250 to Pagani et al., which discloses initial desulfurization in a column by employing a solvent and then the removal of CO.sub.2 by a low temperature distillation; 4,152,129 to Trentham et al., which discloses the separation of CO.sub.2 and methane in a gaseous mixture, with low energy consumption, if large amounts of CO.sub.2 are present; 4,293,322 to Ryan et al., which discloses the distillative separation of CO.sub.2 and H.sub.2 S by adding a C.sub.3 -C.sub.6 akane to increase the relative volatility facilities of the process; and 4,318,723 and 4,350,511 to Holmes et al., which disclose methods of distillative separation of CO.sub.2 and light hydrocarbons by adding a solids preventing agent and lowering the temperature of the CO.sub.2.
Most of the known methods recover acid gas containing H.sub.2 S and CO.sub.2 at low pressures. This recovered acid gas then needs to be processed further in a Sulphur Recovery Unit (SRU), or compressed for injection into a disposal well. Since bulk acid gas removal is primarily a pre-treatment process before a main processing facility, acid gas compression and injection into a disposal well is preferred for handling the waste acid gas stream. However, the high capital and operating cost of removing and disposing of the acid gas using existing processes has been a deterrent to the installation of bulk acid gas removal facilities. Also, sulphur deposition is often a problem with lean sour gas compositions (mainly methane, H.sub.2 S and CO.sub.2, less than 1 mol. % and ethane+), which can plug off piping equipment. When this occurs, the process must be shut down and cleaned either mechanically or by melting the sulphur deposits out.
Therefore, there exists a need in the art for an improved process for separating H.sub.2 S and CO.sub.2 from a sour gas stream in a low cost manner, for use in the field, or before a main processing facility, and for removing and preventing sulphur deposition without shutting down the process.